Ultrasound color flow imaging for oil field applications

ABSTRACT

A system and method for measuring rheology of a treatment fluid. The system may comprise an ultrasound transmitter positioned to direct ultrasound pulses into the treatment fluid as the treatment fluid is being introduced into a wellbore; an ultrasound receiver positioned to receive sound waves reflected from the treatment fluid; and a computer system configured to determine a velocity profile of the treatment fluid based at least in part on the reflected sound waves. The method may comprise introducing a treatment fluid into a wellbore by way of a conduit; directing ultrasound pulses into the treatment fluid; measuring sound waves reflected by the treatment fluid; and determining a velocity profile of the treatment fluid based at least on the measured sound waves.

BACKGROUND

The present disclosure relates to the rheology measurement of a fluidusing ultrasound color flow imaging. More particularly, systems andmethods may be provided that use ultrasound color flow imaging formonitoring fluid rheology in oilfield applications.

Rheology is the science of flow and deformation of matter and describesthe interrelation between force, deformation and time. In simple flows,viscosity is a single parameter that links the rate of shear and theshear stress in the flow field. In industrial fluids, which are complexfluids, the viscosity cannot be represented in terms of a singleparameter and becomes a function of the flow field. In a solid-liquidslurry, the local fluid viscosity not only depends on the localconcentration of the solids but also on the local rate of shear and itsgradient. Often, the solids being transported in the pipeline migrateaway from pipe walls and into the core of the fluid flow within thepipe. As a result, rheology measurements of the fluid near the wall willyield erroneous results relative to the total flow cross section.

Rheological characterization of solid-liquid dispersions may commonly beperformed using off-line measurement devices. For example, shearrheometers and extensional rheometers may be used to determine therheological characterization of a solid-liquid dispersion. Usingoff-line measurement devices may have disadvantages to determiningrheological characterization. A disadvantage may be that once a sampleis withdrawn from a process stream, the rheological properties may beginto change. Often, the fluids to be measured may have rheologies thatintimately depend on the flow field. This dependence is especially truefor colloidal suspensions in which size and fractal dimensions of theclusters or aggregates depend strongly on the environment under whichthey exist. Many of these fluids exhibit shear-dependent viscosity, inthe form of shear thinning or shear-thickening behavior, requiringdetermination of their viscosity at various shear-rates which maycorrespond to the range of shear rates observed in the flow field.Off-line measurements may hardly reproduce the same conditions which mayexist in a real flow field such as shear induced migration of solidparticles. This may make it difficult to obtain representative samplefor off-line measurements of material in a pipeline that may not behomogeneous.

An alternative to off-line measurements may be the use of in-linesystems and/or auxiliary systems which may monitor the rheology of afluid passing through a pipe. Monitoring the rheology, in real-time, ofa fluid within an in-line system and/or an auxiliary system may overcomethe disadvantages found in off-line rheology measurements.

BRIEF DESCRIPTION OF THE DRAWINGS

The features and advantages of certain embodiments will be more readilyappreciated when considered in conjunction with the accompanyingfigures. The figures are not to be construed as limiting any of thepreferred embodiments.

FIG. 1 is a schematic illustration of an example rheology measurementsystem;

FIG. 2 is a schematic illustration of an example rheology measurementsystem with a transmitter and receiver within a single element;

FIG. 3 is a schematic illustration of an example rheology measurementsystem with a transmitter and receiver disposed adjacent to each other;

FIG. 4 is a schematic illustration of a well system;

FIG. 5 is a schematic illustration of an example drilling system; and

FIG. 6 is a schematic of an example drilling system with rheologymeasurement systems positioned within the drilling system.

DETAILED DESCRIPTION

The present disclosure relates to the rheology measurement of a fluidusing ultrasound color flow imaging. As disclosed, a system and methodusing ultrasound may be used to provide a more accurate rheologyprofile. A rheology profile describes the flow of matter through an areaunder an applied force. Measurements of a fluids rheology may providethe strain rate and the different material and/or fluids within themeasured fluid. Rheology measurements of a fluid may be provided bymeasuring the velocity profile within a flow filed. The velocity profilemay be measured with an ultrasound device. An ultrasound device may takemeasurements of velocity by producing ultrasound pulses which may createechoes as the ultrasound pulses reflect off fluid moving within aconfined area. The echoes may be recorded and used to create a velocityprofile.

Rheology of a fluid is conventionally determined by removing fluid froma source and placing it within a rheometer, which may be referred to asoff-line measurements. Off-line measurements, as discussed above, mayhave disadvantages when measuring the rheology of a fluid. Overcomingthese disadvantages may begin with measuring the rheology of a fluidwithin an active system. As disclosed, a rheology measurement systemwithin an active system may overcome the many disadvantages of anoff-line measurement system. In embodiments, an active system may bedefined as an in-line system and/or in an auxiliary system. An auxiliarysystem, also called a pike, may attach to the in-line system. Activesystem measurements of a fluids rheology may be performed with anultrasound imaging device. An ultrasound imaging device may comprise atransducer that converts electrical current into sound waves, which aresent into the fluid. Sound waves bounce off particles in the fluid andare reflected back to the transducer, which converts the waves intoelectrical signals. A computer converts the pattern of electricalsignals into an array of velocities, or even an image, which isdisplayed on a monitor and/or recorded. Producing a series of ultrasoundpulses, an ultrasound device may determine the velocity of a fluidwithin a flow field based on the echoed signal. A color flow displayand/or a Doppler sonogram may be used to illustrate the velocity withinthe flow field. A Doppler ultrasound may measure the movement of echoesthrough an ultrasound signal as a phase change, which may be used forflow velocity calculation, and thus viscosity calculation.

A system for measuring rheology of a treatment fluid may be provided.The system may comprise an ultrasound transmitter positioned to directultrasound pulses into the treatment fluid as the treatment fluid isbeing introduced into a wellbore; an ultrasound receiver position toreceive sound waves reflected form the treatment fluid; and a computersystem configured to determine a velocity profile of the treatment fluidbased at least in part on the reflected sound waves. The ultrasoundtransmitter and the ultrasound receiver may be a single element. Theultrasound transmitter and the ultrasound receiver may be disposed onopposite sides of a conduit comprising flow of the treatment. Theultrasound transmitter and the ultrasound received may be disposed onthe same side of a conduit comprising flow of the treatment fluid. Therheology measurement system may be configured to generate a color flowdisplay of fluid flow in the conduit. The rheology measurement systemmay be configured to generate a Doppler sonogram of fluid flow in theconduit. The treatment fluid may be a fracturing fluid comprisingproppant. The ultrasound transmitter may be positioned to directultrasound pulses into the treatment fluid in the wellbore below thesurface. The system may be disposed inline in a well system.

A method of monitoring rheology of a treatment fluid may be provided.The method may comprise introducing a treatment fluid into a wellbore byway of a conduit; directing ultrasound pulses into the treatment fluid;measuring sound waves reflected by the treatment fluid; and determininga velocity profile of the treatment fluid based at least on the measuredsound waves. The method may further comprise introduction the treatmentfluid into a subterranean formation at or above fracturing pressure ofthe subterranean formation. The ultrasound pulses may be directed intothe treatment fluid while the treatment fluid is flowing through theconduit. The ultrasound pulses may be directed into the treatment fluidin the wellbore below the surface. The method may further comprisegenerating a color flow display of the treatment fluid. The method mayfurther comprise determining viscosity of the treatment fluid based atleast on the determined velocity profile. The method may furthercomprise adjusting concentration of one or more components of thetreatment fluid based at least in part on the velocity profile and/orrheology of the treatment fluid.

A method of monitoring rheology of a treatment fluid may be provided.The method may comprise introducing a treatment fluid into asubterranean formation at or above a fracturing pressure of thesubterranean formation; directing ultrasound pulses into the treatmentfluid while flowing through a conduit fluidically coupled to a wellborepenetrating the subterranean formation; measuring sound waves reflectedby the treatment fluid; and determining a velocity profile of thetreatment fluid based at least on the measured sound waves. Theultrasound pulses may be directed into the treatment fluid in thewellbore below the surface. The method may further comprise generating acolor flow display of the treatment fluid while flowing through theconduit. The method may further comprise adjusting the concentration ofa friction reducer in the treatment fluid based at least in part on thevelocity profile and/or rheology of the treatment fluid.

As illustrated in FIG. 1-3, examples of rheology measurement systems 2may be used to measure the rheology of fluid 4 within a conduit 6. Thefluid may be a solid-containing fluid. Illustrated in FIG. 1, anultrasound transmitter 8 and an ultrasound receiver 10 may be placedacross from each other on opposing sides of conduit 6. Transmitter 8and/or receiver 10 may be attached to an ultrasound imaging deviceand/or a Doppler ultrasound device. Transmitter 8 may be positioned todirect sound waves into the conduit 6. Transmitter 8 may produce aseries of ultrasound pulses which may reflect, or echo, off fluid 4within conduit 6. Ultrasound pulses may be reflected by fluid 4 in avariety of way and directions. These echoes may be received by receiver10 which may send the information to an ultrasound imaging device whichmay produce a visual display of fluid 4 velocity through conduit 6.Taking measurements of fluid 4 in an active system may only require anultrasound device with in-line measurements. When measuring rheology inan auxiliary system, an additional system may be required to takerheology measurements. While not illustrated on FIGS. 1-3, the rheologymeasurement system 2 may further include a control system that includeone or more controllers that direct and regulate performance of thetransmitter 8 and receiver 10. The control system may send signals tothe transmitter 8 and/or receiver 10. The control system may alsocollect and process data from the receiver 10 to determine the velocityprofile of the drilling fluid from which the rheology may be determined.The control system may also directly determine rheology.

A rheology measurement system 2 may comprise additional devices toprepare fluid 4 to be measured. For example, FIG. 1 further illustratesa system in which a pump 12, a heat exchanger 14 (e.g., a heater, acooler, etc.) and/or vanes 16 may be used to prepare fluid 4 formeasurement within conduit 6. A pump 12 may be fluidically coupled tothe conduit 6 and used to move fluid 4 consistently through conduit 6,such as in an auxiliary system, for example. However, many pumps, suchas piston pumps, may not allow fluid 4 to move through conduit 6 at aconsistent velocity. Instead, the pumps may cause fluid 4 to pulsatethrough conduit 6, which may produce inaccurate and/or skewed readings.To prevent pulsating, a pump 12 may comprise one or more pumps whichprevent and/or diminish pulsation of fluid 4. Examples of suitable pumpsmay include syringe pumps, peristaltic pumps, progressive cavity pumps,pulse dampened diaphragm pumps, which may prevent the pulsating of fluid4 through conduit 6. Additionally, pump 12 may be connected to conduit 6through a series of threaded connections. These connections may placepump 12 in-line within the auxiliary system and/or a separate branch offthe auxiliary system.

To produce a steady velocity in fluid 4, the rheology measurement systemmay take advantage of the design of a heat exchanger 14. The heatexchanger 14 may be fluidically coupled to the pump 12 and/or theconduit 6. Fluid 4 may be heated and/or cooled, depending on the currentlocation, use of fluid 4, and climate. For example, the fluid 4 may beat a temperature of 120° to 150° F. to meet API testing requirements. Inexamples, fluid 4 may have a high relative velocity, which may preventtransmitter 8 and/or receiver 10 from producing an accurate reading.This may be a direct result of warm climates and/or fluid 4 excess heatstored within fluid 4 caused by mechanical operations using fluid 4. Insuch examples, fluid 4 may be cooled by heat exchanger 14 to slow thevelocity of fluid 4. A suitable heat exchanger 14 for cooling the fluid4 may comprise peltier devices, resistance band heaters, resistancecartridge heaters, and/or resistance heat trace lines. At times fluid 4may have a relatively low velocity that may prevent transmitter 8 and/orreceiver 10 from producing an accurate reading. This may be caused by acolder climate and/or stagnated fluid 4. The heat exchanger 14 may beused to heat fluid 4 to increase the velocity of fluid 4. A suitableheat exchanger 14 for heating the fluid 4 may comprise a shell and tubetype, plate and frame type, cross-flow type, banked tube, etc.

In some systems, as fluid 4 passes through conduit 6, fluid 4 may tendtoward a turbulent flow regime. One or more flow straightening devicesmay be installed in conduit 6 to restrain the flow of the fluid 4 withinthe conduit 6 and/or to reduce the tendency toward turbulent flow andencourage laminar flow. By way of example, a plurality of vanes 16 maybe used to smooth out fluid 4 and/or direct fluid 4 through conduit 6.The vanes 16 may disposed in the conduit 6 and extend along thelongitudinal axis of the conduit 6 to minimize lateral velocitycomponents in the fluid 4 as it passes through conduit 6. Within conduit6, vanes 16 may comprise concentric circular fins and/or radial fins. Inexamples, there may be a plurality of vanes 16. There may be a range ofvanes 16 from about one vane to about twelve vanes, from about fourvanes to about eight vanes, from about six vanes to about eight vanes.Each vane 16 may be individually controlled and/or controlled as a setor group of vanes 16. This may allow an operator to direct fluid 4 inany manner in an effort to remove inconsistencies within fluid 4. Basedon the system within which fluid 4 may be measured, a rheologymeasurement system 2 may be altered to accommodate any system formsand/or limitations.

In examples, as illustrated in FIGS. 2 and 3, the transmitter 8 andreceiver 10 may be positioned in any manner that may be suitable toproduce an accurate reading. As illustrated in FIG. 2, transmitter 8 andreceiver 10 may be a single device 18 in which both the transmission ofa signal and the receiving of the echo may be performed by the sameunit, for example, an ultrasound transducer. In still other examples, asillustrated in FIG. 3, transmitter 8 and receiver 10 may be placed nextto each other instead of across from each other, as illustrated inFIG. 1. The ability to use multiple locations for transmitters 8 andreceivers 10 may allow for flexibility when performing rheologymeasurements of a fluid 4 within any system. Based on conditions andrequirements, rheology measurement systems 2 may be altered as requiredto satisfy requirements specific to both in-line systems and auxiliarysystems.

Transmitter 8 and receiver 10 may be coupled to a computer system 80that may be coupled to transmitter 8 and receiver 10 by a control line82. Computer system 80 may include a central processing unit 84, amonitor 86, an input device 88 (e.g., keyboard, mouse, etc.) as well ascomputer media 90 (e.g., optical disks, magnetic disks) that can storecode representative of the above-described methods. Computer system 80may be adapted to receive signals from transmitter 8 and receiver 10representative of measurements taken by receiver 10 and signals producedby transmitter 8. Computer system 80 may act as a data acquisitionsystem and possible a data processing system that analyzes themeasurements from receiver 10, for example, to derive rheologymeasurements, including a velocity profile, and track them over time.Measurements taken by receiver 10 may be transmitted to computer system80, these measurements may represent the rheology of a fluid 4 withinpipe 6. The rheology profile in turn may be indicative of thecompositions within fluid 4 in pipe 6, enabling fluid 4 to be tracked,altered, and combined with other elements before being placed downhole.In this manner, receiver 10 measurements may be used to monitor therheology of fluid 6.

Rheology measurement system 2 may be used in a variety of applicationsto measure the rheology of fluid 4 as it passes through conduit 6. Aspreviously mentioned, the rheology measurement system 2 may be anin-line system or an auxiliary system. The rheology measurement system 2may be particularly advantageous for measuring the rheology of drillingfluids (or other solids-containing fluids) in oilfield applications. Byway of example, the rheology measurement system 2 may be used tomeasure, without limitation, drilling fluids, fracturing fluids, andcompletion fluids, among others. In general, the rheology measurementsystem 2 may use a series of ultrasound pulses and their echoed signalto determine the flow velocity. They can be processed to produce, forexample, either a color flow display or a Doppler sonogram. The Dopplerultrasound may measure the movement of the scatters through theultrasound signal as a phase change comparing to the received signal,which can be directly used for flow velocity calculation and thus, theviscosity calculation.

An example may include using the rheology measurement system 2 tomonitor the rheology of a drilling fluid. There are various types ofliquid-based drilling fluids: (1) water-based muds (WBM), whichtypically comprise a water-and-clay based composition, (2) oil-basedmuds (OBM), where the base fluid is a petroleum product, such as dieselfuel, and (3) synthetic-based muds (SBM), where the base fluid is asynthetic oil. In many cases, oil-based drilling fluids also have wateror brine dispersed in the oil in significant proportions. For monitoringof the drilling fluid, the rheology measurement system 2 may beinstalled in-line at one or more locations in a drilling system, such aswithin the drilling mud circulating lines, the drilling pipe, etc. Amongother things, the rheology measurement system 2 may be used to measurethe rheology of the drilling fluid as well as evaluate solids separationefficiency. For example, the rheology measurement system 2 may beinstalled in the drill pipe to provide velocity and rheology propertymeasurements of the drilling fluid in downhole conditions. Alternativelyor in combination with an in-line installation, drilling fluid may belined from one or more locations in the drilling system to a rheologymeasurement system 2 for analysis. In response to the rheologymeasurements, the formulation of the drilling fluid may be changed. Forexample, the oil-water ratio of the drilling fluid may be altered. Inaddition, the concentration of one or more drilling fluid additives,such as emulsifiers, wetting agents, rheology modifiers, weightingagents (e.g., barite), and filtration control additives, among others,may be altered in response to the rheology measurements.

Another example may include using the rheology measurement system 2 tomonitor rheology of a fracturing fluid at one or more points in a wellsystem. In hydraulic fracturing, a fracturing fluid may be introducedinto a subterranean formation at or above the fracture pressure tocreate or enhance one or more fractures in the subterranean formation.The formulations of fracturing fluids may vary, but a typical fracturingfluid may include, without limitation, a linear gel, crosslinked gel, anonviscosified water-based fluid, a gelled oil, a gelled acid, or afoamed fluid. Proppant (e.g., sand, ceramic materials) may be includedin the fracturing fluid to keep the fractures open after treatment. Formonitoring of the fracturing fluid, the rheology measurement system 2comprising the transmitter 8 and receiver 10 may be placed inline at thesurface and/or in the wellbore. Accordingly, the rheology of thefracturing fluid may be modeled at downhole conditions. This may be usedto evaluate the fracturing fluid efficiency in terms of proppanttransport, for example, to visualize the proppant motion in fractureand/or breaker efficiency for fracturing fluid cleanup. The formulationand concentration of a fracturing fluid may then be optimized.

Another example may include using the rheology measurement system 2 toevaluate friction reducer performance. Friction reducers may also bereferred to as drag reducers and may be included in fracturing fluids.Common friction reducers may include synthetic polymers. Currently,friction reducers may be evaluated offsite in a laboratory. However, byinstallation of the rheology measurement system inline, color flowimaging ultrasound may be used for friction reducer evaluation onlocation to provide instant feedback on friction reducer performance.Accordingly, in response to rheology measurements, the concentration ofthe friction reducer in the fracturing fluid and/or the type of frictionreducer used may be modified. Similarly, the rheology measurement system2 may be used in multiphase flow and interstitial flows for boundarylayer determination.

Another example may include using the rheology measurement system 2 at amud plant for drilling fluid analysis. By use of the rheologymeasurement system 2, the viscosity of the drilling fluid may bedirectly obtained from the Doppler ultrasound. In response to therheology measurements, the formulation of the drilling fluid may bechanged. For example, the oil-water ratio of the drilling fluid may bealtered. In addition, the concentration of one or more drilling fluidadditives, such as emulsifiers, wetting agents, rheology modifiers,weighting agents (e.g., barite), and filtration control additives, amongothers, may be altered in response to the rheology measurements.Alternatively or in addition to formula modification, the mixingprocedure (e.g., shear rate) may be changed in response to the rheologymeasurements.

Another example may include using the rheology measurement system 2 in amining operation. In a mining operation, a mining slurry may beproduced, which may be waste stream or may be further processed toextract one or more desirable components. By use of the rheologymeasurement system 2, the components of the mining slurry as well as thesolid concentration in the mining slurry may be determined.

Another example may include using the rheology measurement system 2 forevaluation of particle sedimentation, such as barite sag, in a treatmentfluid. Barite sag may be particularly problematic in a drilling fluidwhere the weighting agent (e.g., barite, calcium carbonate, etc.)separation from the liquid phase. As a result of this particlesedimentation, the drilling fluid may exhibit significant densityvariations in the wellbore. To evaluate at wellbore conditions, therheology measurement system 2 may be used at high temperature and highpressure. Similarly, the rheology measurement system 2 may also be usedfor determination of particle size distribution in a drilling fluid,particularly, when the drilling fluid returns from the wellbore. Suchanalysis may lead to the determination of cutting density and porosity,lost circulation material character, and lost circulation materialefficiency.

Another example may include using the rheology measurement system 2 tobuild a database for simulation and modeling. For example, the rheologybetween the drilling fluid entering and exiting the wellbore may berelated to drilling bit performance. Accordingly, the data obtainedusing the rheology measurement system 2 may be used to predict a numberof drilling characteristics, including rate of penetration.

FIG. 4 illustrates a well system 20 which may a rheology measurementsystem 2. As illustrated, the rheology measurement system 2 may be anin-line system. A well system 20, depicted in FIG. 4, may be used tointroduce treatment fluids (e.g., fracturing fluids) into a wellbore 22.As illustrated in FIG. 4, well system 20 may include a fluid handlingsystem 24 for introducing treatment fluids 26 into wellbore 22 by way oftubular 28. In the illustrated embodiment, fluid handling system 24 isabove surface 30 while wellbore 22 and tubular 28 are below surface 30.Fluid handling system 24 may be configured as shown in FIG. 4 or in adifferent manner, and may include additional or different features asappropriate. Fluid handling system 24 may be deployed via skidequipment, marine vessel deployed, or may be comprised of sub-seadeployed equipment.

As illustrated in FIG. 4, wellbore 22 may include vertical andhorizontal sections and a treatment fluid 26 may be introduced intosubterranean formation 32 surrounding the horizontal portion of wellbore22. Generally, a wellbore 22 may include horizontal, vertical, slant,curved, and other types of wellbore geometries and orientations, andtreatment fluid 26 may generally be applied to subterranean formation 32surrounding any portion of wellbore 22. Wellbore 22 may include a casingthat is cemented or otherwise secured to the wellbore wall. Wellbore 22may be uncased or include uncased sections. Perforations may be formedin the casing to allow treatment fluids 26 and/or other materials toflow into subterranean formation 32. Perforations may be formed usingshape charges, a perforating gun, and/or other tools.

Fluid handling system 24 may include mobile vehicles, mobileinstallations, skids, hoses, tubes, fluid tanks or reservoir, pumps,valves, and/or other suitable structures and equipment. For example,fluid handling system 24 may include pumping equipment 34 and a fluidsupply 36, which both may be in fluid communication with tubular 28.Fluid supply 36 may contain treatment fluid 26. Pumping equipment 34 maybe used to supply treatment fluid 26 from fluid supply 36, which mayinclude tank, reservoir, connections to external fluid supplies, and/orother suitable structures and equipment. Pumping equipment 34 may becoupled to tubular 28 to communicate treatment fluid 26 into wellbore22. Fluid handling system 24 may also include surface and down-holesensors (not shown) to measure pressure, rate, temperature and/or otherparameters of treatment. Fluid handling system 24 may include pumpcontrols and/or other types of controls for starting, stopping and/orotherwise controlling pumping as well as controls for selecting and/orotherwise controlling fluids pumped during the injection treatment. Aninjection control system may communicate with such equipment to monitorand control the injection treatment.

Tubular 28 may include coiled tubing, section pipe, and/or otherstructure that communicate fluid through wellbore 22. Alternatively,tubular 28 may include casing, liners, or other tubular structuresdisposed in wellbore 22. Tubular 28 may include flow control devices,bypass valves, ports, and/or other tools or well devices that control aflow of fluid from the interior of tubular 28 into subterraneanformation 32. For example, tubular 28 may include ports to communicatetreatment fluid 36 directly into the rock matrix of the subterraneanformation 32. Although FIG. 4 illustrates the horizontal section oftubular 28 within inner tubular structure of well system 20, in someembodiments, such inner tubular structure may be absent.

With continued reference to FIG. 4, well system 20 may be used fordelivery of treatment fluid 26 into wellbore 22. Treatment fluid 26 maybe pumped from fluid supply 36 down the interior of tubular 28 inwellbore 22. Treatment fluid 26 may be allowed to flow down the interiorof tubular 28, exit tubular 28, and finally enter subterranean formation32 surrounding wellbore 22. Treatment fluid 26 may also entersubterranean formation 32 at a sufficient pressure to cause fracturingof subterranean formation 32.

As illustrated, the well system 20 may include a rheology measurementsystem 2. While the rheology measurement system 2 is illustrated belowthe surface 30, it is contemplated that one or more rheology measurementsystems may be located above the surface 30 in place of in addition tothe rheology measurement system 2. The rheology measurement system 2 maybe used to measure the rheology of the treatment fluid 26 as it is beingpumped into the subterranean formation 32. By placement below thesurface 30, the rheology measurement system 2 may be used to monitor therheology of the treatment fluid 26 at downhole conditions.

Referring now to FIG. 5, a drilling system 38 is illustrated that mayuse a rheology measurement system 2. As illustrated, the rheologymeasurement system 2 may be an auxiliary system that draws a sample ofthe drilling fluid for analysis. It should be noted that while FIG. 5generally depicts a land-based drilling system, those skilled in the artwill readily recognize that the principles describe herein are equallyapplicable to subsea drilling operations that employ floating orsea-based platforms and rigs, without departing form the scope of thedisclosure.

As illustrated, drilling system 38 may include a drilling platform 40that supports a derrick 42 having a traveling block 44 for raising andlowering a drill string 40. Drill string 46 may include, but is notlimited to, drill pipe and coil tubing, as generally known to thoseskilled in the art. A kelly 48 may support drill string 46 as it may belowered through a rotary table 50. A drill bit 52 may be attached to thedistal end of drill sting 46 and may be driven either by a downholemotor and/or via rotation of drill string 46 form the well surface.Without limitation, drill bit 52 may include, roller cone bits, PDCbits, natural diamond bits, any hole openers, reamers, coring bits, andthe like. As drill bit 52 rotates, it may create a wellbore 22 thatpenetrate various subterranean formations 32.

Drilling system 38 may further include a mud pump 54, one or more solidscontrol system 56, and a retention pit 68. Mud pump 54 representativelymay include any conduits, pipelines, trucks, tubulars, and/or pipes usedto fluidically convey drilling fluid 58 downhole, any pumps,compressors, or motors (e.g., topside or downhole) used to drive thedrilling fluid 58 into motion, any valves or related joints used toregulate the pressure or flow rate of drilling fluid 58, any sensors(e.g., pressure, temperature, flow rate, etc.), gauges, and/orcombinations thereof, and the like.

Mud pump 54 may circulate drilling fluid 58 through a feed conduit 60and to kelly 48, which may convey drilling fluid 58 downhole through theinterior of drill string 46 and through one or more orifices in drillbit 52. Drilling fluid 58 may then be circulated back to surface 30 viaan annulus 62 defined between drill string 46 and the walls of wellbore22. At the surface, the recirculated or spent drilling fluid 58 may beexit the annulus 62 and may be conveyed to one or more solids controlsystem 56 via an interconnecting flow line 66. The solids control system56 may include, but is not limited to, one or more of a shaker (e.g.,shale shaker), a centrifuge, a hydrocyclone, a separator (includingmagnetic and electrical separators), a desilter, a desander, aseparator, a filter (e.g., diatomaceous earth filters), a heatexchanger, and/or any fluid reclamation equipment. The solids controlsystem 56 may further include one or more sensors, gauges, pumps,compressors, and the like used store, monitor, regulate, and/orrecondition the drilling fluid 58.

After passing through the solids control system 56, a “cleaned” drillingfluid 58 may be deposited into a nearby retention pit 68 (e.g., a mudpit). While illustrated as being arranged at the outlet of wellbore 22via annulus 62, those skilled in the art will readily appreciate thatthe solids control system 56 may be arranged at any other location indrilling system 38 to facilitate its proper function, without departingfrom the scope of the disclosure. While FIG. 5 shows only a singleretention pit 68, there could be more than one retention pit 68, such asmultiple retention pits 68 in series. Moreover, the retention put 68 maybe representative of one or more fluid storage facilities and/or unitswhere the drilling fluid additives may be stored, reconditioned, and/orregulated until added to the drilling fluid 58.

As illustrated, the drilling system 38 may include a rheologymeasurement system 2. A fluid sample may be drawn at any desired pointin the drilling system 38. As shown on FIG. 5, the fluid sample may betaken from the retention pit 68. It should be readily understood thatfluid samples may be taken at one or more alternative/additionallocations in the drilling system 38 without imparting form the intendedscope of the present disclosure. The rheology measurement system 2 maybe used to measure the rheology of the drilling fluid 58 as it is beingcirculated in the wellbore 22.

While FIG. 5 illustrates, the rheology measurement system 2 as anauxiliary system, it is contemplated that one or moreadditional/alternative rheology measurement systems may be installedinline in the drilling system 38. Referring now to FIG. 6, an example isshown that include a rheology measurement system 2 disposed inline in adrilling system 38. As illustrated, rheology measurement system 2 may,for example, measure the rheology of drilling fluid 58 at any locationon drilling system 38. FIG. 6 illustrates a schematic of drilling system38, showing multiple positions of rheology measurement system 2.Drilling system 38, within the schematic, comprises drill string 46,kelly 48, drill bit 52, mud pump 54, solids control system 56, annulus62, wellbore 22, flowline 66, retention pit 68, reserve pit 70, and mudmixing hopper 78. Solids control system 56 may further comprise a shaleshaker 72, cones 74, and a centrifuge 76. As an in-line measurementsystem, rheology measurement system 2 may provide real time data aboutthe rheology of drilling fluid 58 passing through different areas indrilling system 38. In examples, multiple rheology measurement systems 2may be used to provide the operator with information in regard to therheology of drilling fluid 58 at different areas of drilling system 38.For example, drilling system 38 may have a range of rheology measurementsystems 2, which may comprise about one to about eight measurementsystems, about three to about six measurement systems, and/or about twoto about four measurement systems.

In examples, an operator may want to know the rheology of the drillingfluid 58 moving through different areas of drilling system 38. Asdiscussed above, there may be a plurality of rheology measurement system2 within drilling system 38. As illustrated in FIG. 6, a rheologymeasurement system 2 may be placed between reserve pit 70 and retentionpit 68, between retention pit 68 and mud pump 54, and between mud pump54 and kelly 48. Placement of rheology measurement systems 2 in theseareas may provide information in regards to the drilling fluid 58 beforeit is sent downhole. Additionally a rheology measurement system 2 may beplaced within flow line 66 before solids control system 56 and betweensolids control system 56 and retention pit 68. This may allowinformation to be gathered about the rheology of the drilling fluid 58as it returns from the wellbore 22 and to identify if the rheology ofthe drilling fluid 58, as “cleaned” by solids control system 56, isacceptable to be placed within retention pit 68. To monitor the rheologyof the drilling fluid 58 as it is “cleaned,” rheology measurementsystems 2 may be placed between shale shaker 72 and cones 74, betweencones 74 and centrifuge 76, and between shale shaker 72 and centrifuge76. Placement of rheology measurements systems 2 may also be foundbetween mud mixing hopper 78 and retention pits 68. In FIG. 6, rheologymeasurement systems 2 are in-line measurements. In examples,measurements may be taken in the same area as illustrated in FIG. 6 butperformed in an auxiliary system, as show in FIG. 5. Additionally, bothin-line measurement systems and auxiliary systems may be used within thesame drilling system 38. In-line measurement systems and auxiliarysystems may be interchangeable and/or adaptable to the presentconditions.

The preceding description provides various embodiments of the systemsand methods of use disclosed herein which may contain different methodsteps and alternative combinations of components. It should beunderstood that, although individual embodiments may be discussedherein, the present disclosure covers all combinations of the disclosedembodiments, including, without limitation, the different componentcombinations, method step combinations, and properties of the system. Itshould be understood that the compositions and methods are described interms of “comprising,” “containing,” or “including” various componentsor steps, the compositions and methods can also “consist essentially of”or “consist of” the various components and steps. Moreover, theindefinite articles “a” or “an,” as used in the claims, are definedherein to mean one or more than one of the element that it introduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, and may bemodified and practiced in different but equivalent manners apparent tothose skilled in the art having the benefit of the teachings herein.Although individual embodiments are discussed, the disclosure covers allcombinations of all of the embodiments. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. Also, the terms in the claimshave their plain, ordinary meaning unless otherwise explicitly andclearly defined by the patentee. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of those embodiments. If there is any conflict in the usages of aword or term in this specification and one or more patent(s) or otherdocuments that may be incorporated herein by reference, the definitionsthat are consistent with this specification should be adopted.

What is claimed is:
 1. A system for measuring rheology of a treatmentfluid comprising: an ultrasound transmitter positioned to directultrasound pulses into the treatment fluid as the treatment fluid isbeing introduced into a wellbore; an ultrasound receiver positioned toreceive sound waves reflected from the treatment fluid; and a computersystem configured to determine a velocity profile of the treatment fluidbased at least in part on the reflected sound waves.
 2. A systemaccording to claim 1, wherein the ultrasound transmitter and theultrasound receiver are a single element.
 3. A system according to claim1, wherein the ultrasound transmitter and the ultrasound receiver aredisposed on opposite sides of a conduit comprising flow of thetreatment.
 4. A system according to claim 1, wherein the ultrasoundtransmitter and the ultrasound received are disposed on the same side ofa conduit comprising flow of the treatment fluid.
 5. A system accordingto claim 1, wherein the rheology measurement system is configured togenerate a color flow display of fluid flow in the conduit.
 6. A systemaccording to claim 1, wherein the rheology measurement system isconfigured to generate a Doppler sonogram of fluid flow in the conduit.7. A system according to claim 1, wherein the treatment fluid is afracturing fluid comprising proppant.
 8. A system according to claim 1,wherein the ultrasound transmitter is positioned to direct ultrasoundpulses into the treatment fluid in the wellbore below the surface.
 9. Asystem according to claim 1, wherein the system is disposed inline in awell system.
 10. A method of monitoring rheology of a treatment fluidcomprising: introducing a treatment fluid into a wellbore by way of aconduit; directing ultrasound pulses into the treatment fluid; measuringsound waves reflected by the treatment fluid; and determining a velocityprofile of the treatment fluid based at least on the measured soundwaves.
 11. A method according to claim 10, further comprisingintroducing the treatment fluid into a subterranean formation at orabove fracturing pressure of the subterranean formation.
 12. A methodaccording to claim 10, wherein the ultrasound pulses are directed intothe treatment fluid while the treatment fluid is flowing through theconduit.
 13. A method according to claim 10, wherein the ultrasoundpulses are directed into the treatment fluid in the wellbore below thesurface.
 14. A method according to claim 10, further comprisinggenerating a color flow display of the treatment fluid.
 15. A methodaccording to claim 10, further comprising determining viscosity of thetreatment fluid based at least on the determined velocity profile.
 16. Amethod according to claim 10, further comprising adjusting concentrationof one or more components of the treatment fluid based at least in parton the velocity profile and/or rheology of the treatment fluid.
 17. Amethod of monitoring rheology of a treatment fluid comprising:introducing a treatment fluid into a subterranean formation at or abovea fracturing pressure of the subterranean formation; directingultrasound pulses into the treatment fluid while flowing through aconduit fluidically coupled to a wellbore penetrating the subterraneanformation; measuring sound waves reflected by the treatment fluid; anddetermining a velocity profile of the treatment fluid based at least onthe measured sound waves.
 18. A method according to claim 17, whereinthe ultrasound pulses are directed into the treatment fluid in thewellbore below the surface.
 19. A method according to claim 17, furthercomprising generating a color flow display of the treatment fluid whileflowing through the conduit.
 20. A method according to claim 17, furthercomprising adjusting the concentration of a friction reducer in thetreatment fluid based at least in part on the velocity profile and/orrheology of the treatment fluid.